In a staged fracturing operation, multiple zones of a formation need to be isolated sequentially for treatment. To achieve this, operators install a fracturing assembly down the wellbore, which typically has a top liner packer, open hole packers isolating the wellbore into zones, various sliding sleeves, and a wellbore isolation valve. When the zones do not need to be closed after opening, operators may use single shot sliding sleeves for the fracturing treatment. These types of sleeves are usually ball-actuated and lock open once actuated. Another type of sleeve is also ball-actuated, but can be shifted closed after opening.
Initially, operators run the fracturing assembly in the wellbore with all of the sliding sleeves closed and with the wellbore isolation valve open. Operators then deploy a setting ball to close the wellbore isolation valve. This seals off the tubing string of the assembly so the packers can be hydraulically set. At this point, operators rig up fracturing surface equipment and pump fluid down the wellbore to open a pressure actuated sleeve so a first zone can be treated.
As the operation continues, operates drop successively larger balls down the tubing string and pump fluid to treat the separate zones in stages. When a dropped ball meets its matching seat in a sliding sleeve, the pumped fluid forced against the seated ball shifts the sleeve open. In turn, the seated ball diverts the pumped fluid into the adjacent zone and prevents the fluid from passing to lower zones. By dropping successively increasing sized balls to actuate corresponding sleeves, operators can accurately treat each zone up the wellbore.
FIG. 1A shows an example of a sliding sleeve 10 for a multi-zone fracturing system in partial cross-section in an opened state. This sliding sleeve 10 is similar to Weatherford's ZoneSelect MultiShift fracturing sliding sleeve and can be placed between isolation packers in a multi-zone completion. The sliding sleeve 10 includes a housing 20 defining a bore 25 and having upper and lower subs 22 and 24. An inner sleeve or insert 30 can be moved within the housing's bore 25 to open or close fluid flow through the housing's flow ports 26 based on the inner sleeve 30's position.
When initially run downhole, the inner sleeve 30 positions in the housing 20 in a closed state. A breakable retainer 38 initially holds the inner sleeve 30 toward the upper sub 22, and a locking ring or dog 36 on the sleeve 30 fits into an annular slot within the housing 20. Outer seals on the inner sleeve 30 engage the housing 20's inner wall above and below the flow ports 26 to seal them off.
The inner sleeve 30 defines a bore 35 having a seat 40 fixed therein. When an appropriately sized ball lands on the seat 40, the sliding sleeve 10 can be opened when tubing pressure is applied against the seated ball 40 to move the inner sleeve 30 open. To open the sliding sleeve 10 in a fracturing operation once the appropriate amount of proppant has been pumped into a lower formation's zone, for example, operators drop an appropriately sized ball B downhole and pump the ball B until it reaches the landing seat 40 disposed in the inner sleeve 30.
Once the ball B is seated, built up pressure forces against the inner sleeve 30 in the housing 20, shearing the breakable retainer 38 and freeing the lock ring or dog 36 from the housing's annular slot so the inner sleeve 30 can slide downward. As it slides, the inner sleeve 30 uncovers the flow ports 26 so flow can be diverted to the surrounding formation. The shear values required to open the sliding sleeves 10 can range generally from 1,000 to 4,000 psi (6.9 to 27.6 MPa).
Once the sleeve 10 is open, operators can then pump proppant at high pressure down the tubing string to the open sleeve 10. The proppant and high pressure fluid flows out of the open flow ports 26 as the seated ball B prevents fluid and proppant from communicating further down the tubing string. The pressures used in the fracturing operation can reach as high as 15,000-psi.
After the fracturing job, the well is typically flowed clean, and the ball B is floated to the surface. Then, the ball seat 40 (and the ball B if remaining) is milled out. The ball seat 40 can be constructed from cast iron to facilitate milling, and the ball B can be composed of aluminum or a non-metallic material, such as a composite. Once milling is complete, the inner sleeve 30 can be closed or opened with a standard “B” shifting tool on the tool profiles 32 and 34 in the inner sleeve 30 so the sliding sleeve 10 can then function like any conventional sliding sleeve shifting with a “B” tool. The ability to selectively open and close the sliding sleeve 10 enables operators to isolate the particular section of the assembly.
Because the zones of a formation are treated in stages with the sliding sleeves 10, the lowermost sliding sleeve 10 has a ball seat 40 for the smallest ball size, and successively higher sleeves 10 have larger seats 40 for larger balls B. In this way, a specific sized ball B dropped in the tubing string will pass though the seats 40 of upper sleeves 10 and only locate and seal at a desired seat 40 in the tubing string. Despite the effectiveness of such an assembly, practical limitations restrict the number of balls B that can be effectively run in a single tubing string.
Depending on the pressures applied and the composition of the ball B used, a number of detrimental effects may result. For example, the high pressure applied to a composite ball B disposed in a sleeve's seat 40 that is close to the ball's outer diameter can cause the ball B to shear right through the seat 40 as the edge of the seat 40 cuts off the sides of the ball B. Accordingly, proper landing and engagement of the ball B and the seat 40 restrict what difference in diameter the composite balls B and cast iron seats 40 must have. This practical limitation restricts how many balls B can be used for seats 40 in an assembly of sliding sleeves 10.
In general, a fracturing assembly using composite balls B may be limited to thirteen to twenty-one sliding sleeves depending on the tubing size involved. For example, a tubing size of 5-½-in. can accommodate twenty-one sliding sleeves 10 for twenty-one different sized composite balls B. Differences in the maximum inner diameter for the ball seats 40 relative to the required outside diameter of the composite balls B can range from 0.09-in. for the smaller seat and ball arrangements to 0.22-in. for the larger seat and ball arrangements. In general, the twenty-one composite balls B can range in size from about 0.9-in. to about 4-in. with increments of about 0.12-in between the first eight balls, about 0.15-in. between the next eight balls, about 0.20-in between the next three balls, and about 0.25-in. between the last two balls. The minimum inner diameters for the twenty-one seats 40 can range in size from about 0.81-in. to about 3.78-in, and the increments between them can be comparably configured as the balls B.
When aluminum balls B are used, more sliding sleeves 10 can be used due to the close tolerances that can be used between the diameters of the aluminum balls B and iron seats 40. For example, forty different increments can be used for sliding sleeves 10 having solid seats 40 used to engage aluminum balls B. However, an aluminum ball B engaged in a seat 40 can be significantly deformed when high pressure is applied against it. Any variations in pressuring up and down that allow the aluminum ball B to seat and to then float the ball B may alter the shape of the ball B compromising its seating ability. Additionally, aluminum balls B can be particularly difficult to mill out of the sliding sleeve 10 due to their tendency of rotating during the milling operation. For this reason, composite balls B are preferred.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.